Associative Polymer Fluid With Clay Nanoparticles For Proppant Suspension

ABSTRACT

Provided herein are methods systems and compositions of a fracturing fluid comprising an associative polymer and clay nanoparticles. A method may comprise: providing a fracturing fluid comprising: a carrier fluid; an associative polymer; and clay nanoparticles; and injecting the fracturing fluid into a subterranean formation at or above a fracture gradient.

BACKGROUND

Hydrocarbon-producing wells are often stimulated by hydraulic fracturingoperations, wherein proppants may be used to hold open or “prop” openfractures created during high-pressure pumping. Once the pumping-inducedpressure is removed, proppants may prop open fractures in the rockformation and thus preclude the fracture from closing. As a result, theamount of formation surface area exposed to the well bore may beincreased, enhancing hydrocarbon recovery rates.

A hydraulic fracturing operation may include pumping a fracturing fluidthrough a wellbore into a subterranean formation. The high pressure maycause the formation to fracture and may allow the fracturing fluid toenter the fractures created in the formation. Fractures may be presentin horizontal directions, vertical directions, and intermediatedirections therein within the subterranean formation. The horizontalcomponent of the fracture is governed by factors that include the fluidvelocity and associated streamlines which help carry proppant to the tipof the fracture. The vertical component is governed by factors thatinclude the particle settling velocity of the proppant and is a functionof proppant diameter and density as well as fluid viscosity and density.

Previously, associative polymers have been added to fracturing fluids toreduce proppant settling within fractures with success. Associativepolymers may exhibit some gelling capability or viscoelasticity whichmay help suspend the proppant in solution and allow the transport ofproppant into the vertical fractures. Although associative polymers havebeen used previously, their use has been limited to lower temperaturewells. Associative polymers tend to have low thermal stability attemperatures above 200° F. (93° C.) leading them to be unsuitable inmedium to high temperature wells.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of the present disclosure, andshould not be used to limit or define the disclosure.

The FIGURE is a schematic view of a well system utilized for hydraulicfracturing.

DETAILED DESCRIPTION

The systems, methods, and/or compositions disclosed herein may relate tosubterranean operations and, in some systems, methods, and compositions,to introduction of a treatment fluid, such as a fracturing fluid, into asubterranean formation penetrated by a wellbore. In particular, afracturing fluid may include a carrier fluid, an associative polymer,and clay nanoparticles for use in wellbores where temperatures exceed200° F. (93° C.). Advantageously, the fracturing fluid may provideimproved proppant suspension at higher temperatures. The treatment maybe performed in an initial fracturing operation or during are-fracturing operation after an initial fracturing operation has beenperformed on the subterranean zone.

An associative polymer may gel when hydrated with water. The associativepolymers may be water soluble colloid polymers that contain hydrophobicdomains. Once hydrated in water, these hydrophobic domains may becapable of self-assembly that may give organized structures and ensuingrheological properties such as the development of gel strength. Thehydrophobically modified monomers used in the polymer's synthesis maycontain hydrophobic chains typically in the C8 to C22 range. Thehydration may cause the associative polymer molecules to interact withone another. The associative polymer may form a network ofpseudo-crosslinks and crosslinks that cause the associative polymer togel in the water. The gelling of the associative polymer may increasethe viscosity of the fluid that is gelled and may aid in proppanttransport. Increased viscosity in a fluid may decrease the rate oramount of proppant settling out of the fluid. As previously mentioned,the vertical component of the fracture is governed by the particlesettling velocity of the proppant. By increasing the viscosity of thefluid, the settling velocity may be slowed and therefore a larger andlonger vertical fracture may be created.

Associative polymers may be used in place of viscoelastic surfactants.The associative polymers offer a hybrid solution that is in one part atypical polymer molecule, however, the polymer may be designed andsynthesized to contain hydrophobic domains that assemble in an aqueousenvironment to provide the structure, viscosity, and elasticity that isotherwise not present in typical hydrating polymers. There may also be ahydrophilic domain within the associative polymer.

More generally, the associative polymers may be based on a hydrophilicbackbone bearing hydrophobic groups of the type obtained by synthesispathways of HASE type (direct synthesis pathway) or of HEUR type (postaddition of hydrophobic groups to a hydrophilic chain). Use mayfurthermore be made of associative polymers resulting from micellarradical polymerization processes by copolymerization of hydrophilicmonomers and hydrophobic monomers within an aqueous dispersant medium(typically water or a water/alcohol mixture) which comprises:hydrophilic monomers in the dissolved or dispersed state in said medium;and hydrophobic monomers in surfactant micelles formed in said medium byintroducing therein this surfactant at a concentration above itscritical micelle concentration (cmc).

The hydrophobic monomers present in surfactant micelles used in micellarpolymerization may be monomers which, by themselves, may have theproperty of forming micelles without needing to add additionalsurfactants. These monomers referred to as being “self-micellizable.”The surfactant used may be the self-micellizable hydrophobic monomeritself, used without other surfactant, although the presence of such anadditional surfactant is not excluded. Thus, for the purposes of thepresent description, when mention is made of hydrophobic monomers insurfactant micelles, this notion encompasses both (i) hydrophobicmonomers present in surfactant micelles other than these monomers, and(ii) monomers comprising at least one hydrophobic part or block andforming by themselves the micelles in aqueous medium. The twoaforementioned embodiments (i) and (ii) are compatible and may coexist.In micellar polymerization, the hydrophobic monomers contained in themicelles are said to be in “micellar solution”. The micellar solution towhich reference is made is a micro-heterogeneous system that isgenerally isotropic, optically transparent and thermodynamically stable.

The associative polymers used according to the present invention arepolymers obtained according to a process that comprises a step (E) ofmicellar radical polymerization in which the following are placed incontact, in an aqueous medium (M): hydrophilic monomers, dissolved ordispersed in said aqueous medium (M); hydrophobic monomers in the formof a micellar solution, namely containing, in the dispersed state withinthe medium (M), micelles comprising these hydrophobic monomers (it beingpossible in particular for this dispersed state to be obtained using atleast one surfactant); at least one radical polymerization initiator,this initiator typically being water-soluble or water-dispersible; andat least one radical polymerization control agent. The aqueous medium(M) used in step (E) is a medium comprising water, preferably in aproportion of about 50% by mass to about 95% by mass, or alternatively,at least about 50% by mass to about 70% by mass, about 70% by mass toabout 90% by mass, or about 90% by mass to about 95% by mass. Thisaqueous medium may optionally comprise solvents other than water, forexample a water-miscible alcohol. Thus, the medium (M) may be, forexample, an aqueous-alcoholic mixture. According to one possiblevariant, the medium (M) may comprise other solvents, preferably in aconcentration in which said solvent is water-miscible, which mayespecially make it possible to reduce the amount of stabilizingsurfactants used. For example, the medium (M) may comprise pentanol, orany other additive for adjusting the aggregation number of thesurfactants. In general, it is preferable for the medium (M) to be acontinuous phase of water consisting of one or more solvents and/oradditives that are miscible with each other and in water in theconcentrations at which they are used. For the purposes of the presentdescription, the term “radical polymerization control agent” means acompound that is capable of extending the lifetime of the growingpolymer chains in a polymerization reaction and of giving thepolymerization a living or controlled nature. This control agent istypically a reversible transfer agent as used in controlled radicalpolymerizations denoted by the terminology RAFT or MADIX, whichtypically use a reversible addition-fragmentation transfer process. Theradical polymerization control agent used in step (E) may be a compoundwhich comprises a thiocarbonylthio group —S(C═S)— or it may be acompound which comprises a xanthate group (bearing —SC═S—O— functions),for example a xanthate. According to one particular embodiment, thecontrol agent used in step (E) may be a polymer chain derived from acontrolled radical polymerization and bearing a group that is capable ofcontrolling a radical polymerization. Thus, for example, the controlagent may be a polymer chain (in general, hydrophilic orwater-dispersible) functionalized at the chain end with a xanthate groupor more generally comprising a group —SC═S—, for example obtainedaccording to the MADIX technology. Alternatively, the control agent usedin step (E) may be a non-polymeric compound bearing a group that ensuresthe control of the radical polymerization, especially a thiocarbonylthiogroup —S(C═S)—. The radical polymerization control agent used in step(E) may be a polymer, or an oligomer, of water-soluble or waterdispersible nature and bearing a thiocarbonylthio group —S(C═S)—, forexample a xanthate group —SC═SO—. This polymer, which is capable ofacting both as a polymerization control agent and as a monomer in step(E), is also may be referred to as a “prepolymer.” Typically, thisprepolymer is obtained by radical polymerization of hydrophilic monomersin the presence of a control agent bearing a thiocarbonylthio group—S(C═S)—, for example a xanthate. In this step, the following maytypically be placed in contact: hydrophilic monomers, such as to thoseused in step (E); a radical polymerization initiator; and a controlagent bearing a thiocarbonylthio group —S(C═S)—, for example a xanthate.The use of the abovementioned step prior to step (E) makes it possible,schematically, to hydrophilize a large number of control agents bearingthiocarbonylthio functions (for example xanthates, which may behydrophobic by nature), by converting them from prepolymers that aresoluble or dispersible in the medium (M) of step (E). A prepolymersynthesized in the above step may have a short polymer chain, forexample comprising a sequence of less than 50 or less than 25 monomerunits, for example between 2 and 15 monomer units. The conditions ofstep (E) may make it possible to combine the advantages both ofcontrolled radical polymerization and of micellar polymerization. Thepresence of micelles in the polymerization medium may not affect theaction of the control agents, which make it possible to perform acontrolled polymerization of the monomers present in the aqueous mediumin a similar manner to a controlled radical polymerization performed inhomogeneous medium, thus making it possible very readily to predict andcontrol the average molar mass of the synthesized polymer (this mass isproportionately higher the lower the initial concentration of controlagent in the medium, this concentration dictating the number of growingpolymer chains).

In addition to this control of the polymerization of the monomers, notobtained in the more usual micellar polymerization processes, the use ofstep (E) of the process of the invention in addition may make itpossible, also completely attain polymers having both a large andcontrolled size. Under the conditions of step (E), it may be possible tocontrol the number-average molar mass of the polymers which makes itpossible, inter alia, to produce polymers having low masses. Theassociative polymer present in the fracturing fluid may be synthesizedaccording to the aforementioned step (E) and has a mass of between 50000 and 10 000 000, preferably of between 750 000 and 5 000 000 g/mol,in particular between 1 000 000 and 4 000 000 g/mol. Such polymers maybe used at a concentration below their critical overlap concentration.On account of their small sizes, such polymers may diffuse at theinterfaces and participate in modifying the properties of theseinterfaces or surfaces.

The associative polymer may have a molecular weight in the range fromabout 10,000 Daltons to about 10,000,000 Daltons. The molecular weightrange from about 500,000 Daltons to about 1,500,000 Daltons. Thismolecular weight may vary between individual molecules of theassociative polymer in the treatment fluid (e.g., a range of molecularweights may be present in a treatment fluid). One of ordinary skill inthe art with the benefit of this disclosure should recognize theappropriate size for a given application.

Suitable associative polymers generally may include, but are not limitedto, acrylamide, methacrylamide, acrylate, and methacrylate polymers. Ingeneral, the polymers may be partially hydrolyzed to introduce somecarboxylic groups into the chain. The presence of these charged unitsmay improve water solubility and may increase hydrodynamic volume of thechain due to the mutual repulsion of the negative charges.

The polymer includes one or more hydrophobic segments. As used herein,the term “hydrophobic segment” refers to the portion of the associativepolymer additive having at least one hydrophobe. In an embodiment, thehydrophobe may include from 1 to 24 carbon atoms, 4 to 24 carbon atoms,or 10 to 24 carbon atoms, and may include saturated, unsaturated,aliphatic (including linear, cyclic, and branched aliphatic compounds orgroups), and/or aromatic compounds or groups. Suitable hydrophobes mayinclude, but are not limited to, linear or branched alkyl, alkenyl,cycloalkyl, aryl, alkaryl, aralkyl hydrocarbons, and halo-substitutedalkyl, cycloalkyl, aryl, alkylaryl, acryloyl, arylakyl hydrocarbons, andmixtures thereof. While not wishing to be limited by theory, thehydrophobic segments are believed to form associations via, e.g.,physical crosslinks, Van der Waals forces, and/or electrostaticinteractions with each other or with additional components in thetreatment fluid.

The hydrophobic segment may be connected to the water-soluble polymerbackbone through a coupling functional group. The coupling functionalgroups of the associative polymer may provide the reactivity and bondingsites to chemically bond the water-soluble polymer backbone to thehydrophobic segment. The coupling functional group may generally includeany functional group capable of forming a bond between the water-solublepolymer backbone and a hydrophobe. The coupling functional group mayinclude, but is not limited to, a group such as a hydroxyl, a carboxyl,an ether, an ester, a sulfhydryl, and an isocyanate, derivativesthereof, or combinations thereof. Other coupling functional group mayinclude, but are not limited to, an amino group, an ethylenicunsaturated group, an epoxide group, a carboxylic acid group, acarboxylic ester group, a carboxylic acid halide group, an amide group,a phosphate group, a sulfonate group, a sulfonyl halide group, anorganic silane group, an acetylene group, a phenol group, a cycliccarbonate group, an isocyanate group, and a carbodiimide group.

The number of hydrophobic segments per molecule of the associativepolymer should be sufficient to generate intermolecular interactions inan aqueous solution to allow for the formation of an associative polymernetwork. An associative polymer network may be a mass of associativepolymer molecules that are interacting in a solution thoughintermolecular forces. The associative polymer may generally include,but is not limited, at least 0.25 to about 25 hydrophobic segments permolecule. The associate polymer may include from about 0.5 to about 10hydrophobic segments per molecule. The number of hydrophobic segmentsper molecule of the associative polymer may be altered throughvariations in the reactant concentrations during manufacturing of theassociative polymer additive.

The hydrophobic segments on the associative polymer may include, but arenot limited to, from about 5% to about 50% by weight of the totalassociative polymer. Alternatively, the hydrophobes may be present inthe associative polymer in any amount, including, but is not limited,from about 10% to about 40%, or about 5% to about 40%, or about 15% toabout 30% by weight of the total associative polymer molecule. As notedabove, the weight fraction of the hydrophobe portion of the moleculeshould be sufficient to generate the desired intermolecular interactionsbetween the associative polymer molecules in an aqueous solution.

The associative polymer that may be used to form the associative polymernetworks of the present disclosure may be synthesized by incorporatinghydrophobic segments within a water-soluble polymer backbone using anysuitable method. Suitable methods include chain growth polymerization,step growth polymerization, and post-polymerization mechanisms fornaturally occurring polymers and polymers that were made by chain orstep growth polymerization. Specific examples may include, but are notlimited to: reacting hydrophobes with a water-soluble polymer reactantcontaining coupling groups or corresponding coupling group pre-cursorsto form the associative polymer additive; reacting condensation monomersand/or prepolymers along with a coupling group precursor to formcondensation polymers, wherein one of the reactants provides therequisite hydrophobe content on the final associative polymer additive;and reacting olefinically unsaturated monomers and/or prepolymers byaddition polymerization, wherein at least one of the reactants containsthe requisite hydrophobe content for the final associative polymeradditive. In most instances, this is not post-polymerizationmodification. Thus, the hydrophobic modification is incorporated withinthe polymer structure as it forms. However, in some instances, thismodification may be performed post-polymerization, for example, througha suitable modification reaction. Residual monomer may remain in thepolymer.

The degree of rheological modification attributable to the associativepolymer additive may depend on a variety of factors, including, but notlimited to, the degree of hydrophobic modification on the associativepolymer additive, the microstructure of the associative polymeradditive, and the concentration of the associative polymer additive inthe treatment fluid. Intrapolymer interactions may become more prominentat low polymer concentrations and high hydrophobic segment density alongthe water-soluble polymer backbone. In such instances, a compact,globular conformation may be formed giving rise to organized,hydrophobic microdomains in the network with micelle-like properties. Inalternative, interpolymer interactions may be more prominent, usually atlower hydrophobe/water-soluble polymer backbone ratios and at higherassociative polymer additive concentrations. A high associative polymeradditive concentration may lead to chain overlap and hydrophobicclustering that increases the viscosity of the treatment fluid byforming an associative polymer network. One of ordinary skill in theart, with the benefit of this disclosure, will recognize the conditionsnecessary to obtain the proper intrapolymer and interpolymerassociations to form the associative polymer networks of the presentinvention.

Associative polymers may be included in the fracturing fluid in anyamount suitable for a particular amount to create a fluid with thedesired rheological properties such as viscosity, including, but notlimited to, an amount of about 1 lb/1000 gal (0.1198 kg/m³) to about 60lb/1000 gal (7.188 kg/m³). Alternatively, about 1 lb/1000 gal (0.1198kg/m³) to about 5 lb/1000 gal (0.6 kg/m³), about 5 lb/1000 gal (0.6kg/m³) to about 15 lb/1000 gal (1.797 kg/m³), about 15 lb/1000 gal(1.797 kg/m³) to about 25 lb/1000 gal (2.995 kg/m³), about 25 lb/1000gal (2.995 kg/m³) to about 30 lb/1000 gal (3.594 kg/m³), about 30lb/1000 gal (3.594 kg/m³) to about 50 lb/1000 gal (5.99 kg/m³), or about50 lb/1000 gal (5.99 kg/m³) to about 60 lb/1000 gal (7.188 kg/m³). Asused herein, lb/1000 gal refers to pounds of associative polymer per1000 gallons of fluid the associative polymer is added to.

As previously mentioned, associative polymers have low thermal stabilityand will generally not work in wells above 200° F. Bonds formed with theassociative polymer to oil, water, and other associative polymermolecules may be weak and therefore may be sensitive to elevatedtemperatures. High temperatures may lead to decreased gellingperformance of the associative polymer. If the temperature is too high,the associative polymer may completely lose the ability gel and theproppant may settle out of the fluid. Although polymer gel stabilizershave been used to increase thermal stability of existing fracturingfluids including associative polymers, the gel stabilizers incombination with associative polymers fail to provide fluids withproppant suspension for long durations, especially at elevatedtemperatures.

Clay nanoparticles may be included in the fracturing fluid to increasethe thermal stability of associative polymers. Clay nanoparticles may beclay particles with at least one dimension such as length, width,thickness, or cross-section, of less than 1 micron. Clay nanoparticlesmay impart an additional interactive surface within the network ofhydrated associated polymer. The clay nanoparticles may migrate to theinterstitials between hydrated associative polymers and thereby interactwith the molecules. Additional surface interaction may improve andextend the thermal stability of the network of associative polymer gelallowing the associative polymer to be used in applications above 200°F.

The clay nanoparticles may include any clay that exhibits the desiredproperties of surface interaction. Clays may be selected based on otherproperties they exhibit in solution such as increased viscosity orgelling and thermal-viscosity stability. In particular, clays may,without limitation, be selected from the smectite group (smectites),modified clays, synthetic clays, and hectorite. In some examples, theclay may include a hectorite clay. Hectorite clay may be especiallyadvantageous as illustrated in selected examples below. Other clays fromthe smectite group that potentially may be used include clays such asmontmorillonite and bentonite. The clay may be a synthetic clay or anaturally occurring clay. Some examples of a synthetic clay may include,but are not limited to, a synthetic hectorite or a synthetic bentonite.The clay nanoparticles may be included in any amount to create a fluidwith the desired viscosity and other properties, including, but notlimited to, an amount of about 0.5% to about 10% by weight of theassociative polymer. Alternatively, the clay nanoparticles may beincluded in an amount of about 0.5% to about 1%, about 0.5% to about 5%,about 1% to about 5%, about 5% to about 10%, about 10%, or about 1% toabout 2% by weight of the associative polymer. One of ordinary skill inthe art, with the benefit of this disclosure, should be able to selectan appropriate kind and amount of clay nanoparticles for a particularapplication.

The clay nanoparticles may have a mean particle size of less than about200 nanometers (nm). One of ordinary skill in the art should be able todetermine a mean particle size with standard laboratory equipment suchas automated particle size analyzers, such as by laser diffraction witha Malvern Mastersizer™ 3000 laser diffraction particle size analyzer.The clay nanoparticles may have a mean particle size at a point of about1 nm, about 2 nm, about 3 nm, about 4 nm, about 50, about 100, about150, about 197 nm, about 198 nm, about 199 nm, or about 200 nm. The meanparticle size of the nanoparticles may be in the range of from about 1nm to about 50 nm. The mean particle size of the solid nanoparticles maybe in the range of from about 5 nm to about 50 nm. The mean particlesize of the solid nanoparticles may be in the range of from about 5 nmto about 200 nm. One of ordinary skill in the art, with the benefit ofthis disclosure, should be able to determine the appropriate size of thesolid nanoparticles in the treatment fluid for a particular application.

As previously mentioned a fracturing fluid may include a carrier fluid,an associative polymer, and clay nanoparticles. Examples of carrierfluids may include, but are not limited to, aqueous fluids, non-aqueousfluids, slickwater fluids, aqueous gels, viscoelastic surfactant gels,foamed gels, and emulsions, for example. Examples of suitable aqueousfluids may include, but are not limited to, fresh water, saltwater,brine, seawater, and/or any other aqueous fluid that may not undesirablyinteract with the other components used in accordance with the presentdisclosure or with the subterranean formation. Examples of suitablenon-aqueous fluids may include, but are not limited to, organic liquids,such as hydrocarbons (e.g., kerosene, xylene, toluene, or diesel), oils(e.g., mineral oils or synthetic oils), esters, and any combinationthereof. Suitable slickwater fluids may generally be prepared byaddition of small concentrations of polymers to water to produce what isknown in the art as “slick-water.” Suitable aqueous gels may generallyinclude an aqueous fluid and one or more gelling agents. Suitableemulsions may be included of two immiscible liquids such as an aqueousfluid or gelled fluid and a hydrocarbon. Foams may be created by theaddition of a gas, such as carbon dioxide or nitrogen. Additionally, thecarrier fluid may be an aqueous gel included of an aqueous fluid, agelling agent for gelling the aqueous fluid and increasing itsviscosity, and, optionally, a crosslinking agent for crosslinking thegel and further increasing the viscosity of the fluid. The increasedviscosity of the gelled, or gelled and crosslinked, treatment fluid,inter alia, may reduce fluid loss and may allow the carrier fluidtransport significant quantities of suspended particulates. The densityof the carrier fluid may be increased to provide additional particletransport and suspension in some applications.

The fracturing fluid may include any number of optional additives,including, but not limited to, salts, acids, fluid loss controladditives, gas, foamers, corrosion inhibitors, scale inhibitors,catalysts, clay control agents, biocides, friction reducers, ironcontrol agent, antifoam agents, bridging agents, dispersants, hydrogensulfide (“H₂S”) scavengers, carbon dioxide (“CO₂”) scavengers, oxygenscavengers, lubricants, viscosifiers, breakers, weighting agents, inertsolids, emulsifiers, emulsion thinner, emulsion thickener, surfactants,lost circulation additives, pH control additive, buffers, crosslinkers,stabilizers, chelating agents, mutual solvent, oxidizers, reducers,consolidating agent, complexing agent, particulate materials and anycombination thereof. With the benefit of this disclosure, one ofordinary skill in the art should be able to recognize and select asuitable optional additive for use in the fracturing fluid.

The fracturing fluid may further include other additives. The additivesmay include a dispersing agent. Dispersing agents may include anychemical that disrupts the surface interactions of proppant andpotential flocculating agents in the fracturing fluid. Some examples ofdispersants may include, but are not limited to, aminosilanes, acaciagum, acrylamide copolymer, acrylate copolymers and their ammonium salts,acrylic acid homopolymer, carboxylate and sulfonate copolymer,coglycerides, dicaprylyl carbonate, maleic anhydride,phosphinocarboxylic acid, polyacrylic acid, propylheptyl caprylate,sodium acrylate homopolymer, and sodium nitrite. The additives may bepresent in any concentration, including, but not limited to, an amountof about 1 to about 50 gallons per thousand (OPT) which is equivalent toabout 1 to about 0.50 liters per thousand (LPT). Alternatively, about 1to about 10 GPT (LPT), about 10 to about 20 GPT (LPT), about 20 to about30 GPT (LPT), about 30 to about 40 GPT (LPT), about 40 to about 50 GPT(LPT), about 1 to about 25 GPT (LPT), or about 25 to about 50 GPT (GPT).GPT and LPT refer to gallons of additive per thousand gallons of fluidthe additive is placed in. One of ordinary skill in the art, with thebenefit of this disclosure, should be able to select appropriateadditives and concentrations for a particular application.

The fracturing fluid may further include a proppant. Proppants mayinclude any suitable material. In general, particles of the proppantshould have a crush strength higher than the fracture gradient of theformation so as to avoid crushing the proppant. Proppants should also beresistant to chemical attack from chemicals present in the subterraneanformation and from chemicals added to the fracturing fluid. Somesuitable proppants may include, but are not limited to, silica sand,calcium carbonate sand, resin coated sand, ceramic proppants, fly ash,and sintered bauxite. Other solid particulates suitable of use asproppant particulates may include fly ash, desert sand, beach sand,brown sand, white sand, ceramic heads, glass heads, bauxite grains,sized calcium carbonate, and walnut shell fragments. The proppantparticulates may include any density. In some examples, proppantparticulates may be classified as lightweight or low density and mayhave a density of about 1.25 g/cm³ to about 2.2 g/cm³. Using low densityproppant have several advantages including but not limited to increasedconductivity, easier placing with low viscosity fluids, and more uniformdistribution within a fracture. Proppant may include any shape,including but not limited, to spherical, toroidal, amorphous, planar,cubic, or cylindrical. Proppant may further include any roundness andsphericity. Without limitation, the proppant may have a mean particlesize in a range from about 2 mesh to about 400 mesh, U.S. Sieve Series.By way of example, the proppant may have a particle size of about 10mesh to about 70 mesh with distribution ranges of 10-20 mesh, 20-40mesh, 40-60 mesh, or 50-70 mesh, depending, for example, on the particlesizes of the formation particulates to be screen out. Proppants may alsoinclude micro-proppants. As used herein, the term “micro-proppant”refers to proppant having a mean particle size of less than about 150microns. Micro-proppants may include any suitable particle size.Micro-proppants may include a mean particle size from about 0.01 micronto about 500 microns, about 0.1 micron to about 100 microns, about 100microns to about 200 microns, about 200 microns to about 300 microns,about 300 microns to about 400 microns, about 400 microns to about 500microns, about 1 micron to about 250 microns, or about 250 microns toabout 500 microns.

Proppants may be present in the fracturing fluid in any concentration orloading. Without limitation, the proppant particulates may be present inan amount of about 1 pounds per gallon (“lb/gal”) (0.1198 kg/L) to about20 lb/gal (2.396 kg/L), about 1 lb/gal (0.1198 kg/L) to about 5 lb/gal(0.0.6 kg/L), about 5 lb/gal (0.6 kg/L) to about 10 lb/gal (1.198 kg/L),about 10 lb/gal (1.198 kg/L) to about 15 lb/gal (1.797 kg/L), about 15lb/gal (1.797 kg/L) to about 20 lb/gal (2.396 kg/L), about 1 lb/gal(0.1198 kg/L) to about 10 lb/goal (1.198 kg/L), or about 10 lb/gal(1.198 kg/L) to about 20 lb/gal (2.396 kg/L). With the benefit of thisdisclosure, one of ordinary skill in the art should be able to select anappropriate proppant and loading.

The proppant may include an electrically charged surface. In someexamples, the proppant surface charge may be negative or anionic. Somefracturing fluid additives may include surface charges that are oppositeof the proppant. In some examples, clay control agents and frictionreducing agents may include positive surface charges. In solution, theparticles of opposite charges may interact which may cause the proppantto flocculate and fall out of solution. The addition of a dispersingagent may reduce the interactions between the opposite-charged moleculesthereby reducing or eliminating the flocculating of proppant.

A fracturing fluid may be prepared in any suitable way. One method forpreparing a fracturing fluid including an associative polymer mayinclude hydrating an associative polymer and then adding the hydratedpolymer and clay nanoparticles to a carrier fluid.

Statement 1. A method comprising: providing a fracturing fluidcomprising: a carrier fluid; an associative polymer; and claynanoparticles; and injecting the fracturing fluid into a subterraneanformation at or above a fracture gradient.

Statement 2. The method of statement 1 further comprising hydrating theassociative polymer prior to combining the associative polymer with thecarrier fluid.

Statement 3. The method of statement 1 or statement 2 wherein thecarrier fluid comprises an aqueous fluid or a slickwater fluid.

Statement 4. The method of any preceding statement wherein theassociative polymer comprises a acrylamide polymer, methacrylamidepolymer, acrylate polymer, methacrylate polymer, or combinationsthereof.

Statement 5. The method of any preceding statement wherein theassociative polymer comprises at least one hydrophobe.

Statement 6. The method of statement 4 wherein the at least onehydrophobe comprises from 1 to 24 carbons.

Statement 7. The method of any preceding statement wherein the claynanoparticles comprise hecrotite, smectite, or combinations thereof.

Statement 8. The method of any preceding statement wherein the claynanoparticles are present in an amount of about 0.5% to about 10% byweight of the associative polymer.

Statement 9. The method of any preceding statement wherein the claynanoparticles have a mean particle size of less than 200 nm.

Statement 10. The method of any preceding statement wherein thefracturing fluid further comprises a proppant.

Statement 11. The method of any preceding statement wherein the step ofinjecting comprises alternately injecting a proppant laden fluid and aproppant free fluid.

Statement 12. The method of any preceding statement wherein thesubterranean formation comprises at least one zone comprising atemperature of above 200° F.

Statement 13. The method of any preceding statement wherein the step ofinjecting comprises injecting into a tubular penetrating a subterraneanformation, wherein the tubular is connected to a pump configured todeliver the fracturing fluid though the tubular into the subterraneanformation.

Statement 14. The method of any preceding statement wherein the step ofproviding comprises hydrating the associative polymer.

Statement 15. The method of statement 14 wherein the associative polymeris hydrated in a hydration tank.

Statement 16. A fracturing fluid comprising: a carrier fluid; anassociative polymer; and clay nanoparticles.

Statement 17. The fracturing fluid of statement 16 wherein theassociative polymer comprises a acrylamide polymer, methacrylamidepolymer, acrylate polymer, methacrylate polymer, or combinationsthereof.

Statement 18. The fracturing fluid of statement 16 or 17 wherein theassociative polymer is present in an amount of about 1 lb/1000 gal toabout 30 lb/1000 gal.

Statement 19. The composition of any one of statements 16 to 18 whereinthe clay nanoparticles comprise hecrotite, smectite, or combinationsthereof.

Statement 20. The composition of any one of statements 16 to 19 whereinthe clay nanoparticles are present in an amount of about 0.5% to about10% by weight of the associative polymer.

According to the present disclosure, a fracture may be created and/orextended by any suitable means. Such means are well-known to thoseskilled in the relevant art. For example a common method may includeinjecting a pre-pad or pad fluid, to initiate the fracturing of asubterranean formation prior to the injection of a proppant. In suchexamples, the pre-pad or pad fluid may be proppant-free or substantiallyproppant-free. The proppant may be suspended in a slurry with anassociative polymer and clay nanoparticles as previously described whichmay be injected into the subterranean formation to create and/or extendat least one fracture. In order to create and/or extend a fracture, afracturing fluid is typically injected into the subterranean formationat a rate sufficient to generate a pressure above the fracture gradient.

Fracking operations can involve packing relatively high volumes ofproppant within a fracture. In such operations, a single homogeneousproppant pack is typically formed, which may be used to abut thefracture so that production fluids can be recovered through to therelatively small interstitial spaces between the tightly packedproppant. In some methods of the present application, a fracturing fluidmay be introduced into a subterranean formation after the pre-pad or padfluid. The fracturing fluid may include the associative polymer, claynanoparticles, and the carrier fluid. The fracturing fluid may beinjected in small volumes and alternated between proppant-free andproppant-laden fluid. The proppant-free fluid intermittently injectedinto the fracture with the fracturing fluid that is proppant laden willbe referred to herein as a “spacer fluid.” This spacer fluid may be anysuitable fluid such as, without limitation, water, slickwater, or anaqueous gel including an aqueous base fluid, and a gelling agent (suchas an associative polymer). The spacer fluid may be the same fluid asthe fracturing fluid including the proppant particulates without theproppant particles.

A method of treating a subterranean formation may include creating atleast one fracture in the subterranean formation, providing a fracturingfluid, providing a spacer fluid, alternately injecting a spacer fluidand the fracturing fluid into the fracture such that a proppant isdisposed in the fracture. Creating the fracture may include injecting afracturing fluid that is proppant-free into the subterranean formationat a pressure that is above a fracture gradient. The step of providing afracturing fluid may include hydrating the associative polymer andadding the hydrated polymer, clay nanoparticles, and carrier fluid to aholding or mixing tank. The hydrating fluid may be the same as thecarrier fluid. The method may further include flowing back the injectedfluids from the fracture to remove at least a portion of the fluids fromthe fracture such that the subterranean formation fluids may enter thefracture. The fracturing fluid may be transported into the subterraneanformation through a tubular and the spacer fluid may be transported intothe subterranean formation through an annulus between the tubular andthe subterranean formation or thought the same tubular as the fracturingfluid.

In various examples, systems configured for delivering the treatmentfluids described herein to a downhole location are described. In variousexamples, the systems can include a pump fluidly coupled to a tubular,the tubular containing fracturing fluid including a proppant or afracturing fluid without proppant.

The pump may be a high pressure pump in some examples. As used herein,the term “high pressure pump” will refer to a pump that is capable ofdelivering a fluid downhole at a pressure of about 1000 psi or greater.A high pressure pump may be used when it is desired to introduce thetreatment fluid to a subterranean formation at or above a fracturegradient of the subterranean formation, but it may also be used in caseswhere fracturing is not desired. In some examples, the high pressurepump may be capable of fluidly conveying particulate matter, such asproppant, into the subterranean formation. Suitable high pressure pumpswill be known to one having ordinary skill in the art and may include,but are not limited to, floating piston pumps and positive displacementpumps.

In other examples, the pump may be a low pressure pump. As used herein,the term “low pressure pump” will refer to a pump that operates at apressure of about 1000 psi or less. In some examples, a low pressurepump may be fluidly coupled to a high pressure pump that is fluidlycoupled to the tubular. That is, in such examples, the low pressure pumpmay be configured to convey the treatment fluid to the high pressurepump. In such examples, the low pressure pump may “step up” the pressureof the treatment fluid before it reaches the high pressure pump.

In some examples, the systems described herein can further include amixing tank that is upstream of the pump and in which the treatmentfluid is formulated. In various examples, the pump (e.g., a low pressurepump, a high pressure pump, or a combination thereof) may convey thetreatment fluid from the mixing tank or other source of the treatmentfluid to the tubular. In other examples, however, the treatment fluidcan be formulated offsite and transported to a worksite, in which casethe treatment fluid may be introduced to the tubular via the pumpdirectly from its shipping container (e.g., a truck, a railcar, a barge,or the like) or from a transport pipeline. In either case, the treatmentfluid may be drawn into the pump, elevated to an appropriate pressure,and then introduced into the tubular for delivery downhole

The FIGURE shows an illustrative schematic of a system that can deliverthe fracturing fluids described herein to a downhole location, accordingto one or more examples. It should be noted that while the FIGUREgenerally depicts a land-based system, it is to be recognized that likesystems may be operated in subsea locations as well. As depicted in theFIGURE, system 1 may include mixing tank 10, in which a fracturing fluidmay be formulated. The fracturing fluid may be conveyed via line 12 towellhead 14, where the fracturing fluid enters tubular 16, tubular 16extending from wellhead 14 into subterranean formation 18. Upon beingejected from tubular 16, the fracturing fluid may subsequently penetrateinto subterranean formation 18. Pump 20 may be configured to raise thepressure of the fracturing fluid to a desired degree before itsintroduction into tubular 16. The fracturing fluid may be introducedinto subterranean formation 18 at any stage of a fracturing operation.For example, the fracturing fluid may be introduced into thesubterranean formation 18 after one or more factures have beeninitiated. Fractures may be introduced for example by a pad stage. It isto be recognized that system 1 is merely exemplary in nature and variousadditional components may be present that have not necessarily beendepicted in the FIG. 1n the interest of clarity. Non-limiting additionalcomponents that may be present include, but are not limited to, supplyhoppers, valves, condensers, adapters, joints, gauges, sensors,compressors, pressure controllers, pressure sensors, flow ratecontrollers, flow rate sensors, temperature sensors, and the like.

Although not depicted in the FIGURE, the fracturing fluid may, in someexamples, flow back to wellhead 14 and exit subterranean formation 18.In some examples, the fracturing fluid that has flowed back to wellhead14 may subsequently be recovered and recirculated to subterraneanformation 18.

It is also to be recognized that the disclosed treatment fluids may alsodirectly or indirectly affect the various downhole equipment and toolsthat may come into contact with the treatment fluids during operation.Such equipment and tools may include, but are not limited to, wellborecasing, wellbore liner, completion string, insert strings, drill string,coiled tubing, slickline, wireline, drill pipe, drill collars, mudmotors, downhole motors and/or pumps, surface-mounted motors and/orpumps, centralizers, turbolizers, scratchers, floats (e.g., shoes,collars, valves, etc.), logging tools and related telemetry equipment,actuators (e.g., electromechanical devices, hydromechanical devices,etc.), sliding sleeves, production sleeves, plugs, screens, filters,flow control devices (e.g., inflow control devices, autonomous inflowcontrol devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like. Any of thesecomponents may be included in the systems generally described above anddepicted in FIG. 1.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of some of the systems, methodsand cement compositions are given. In no way should the followingexamples be read to limit, or define, the entire scope of thedisclosure.

Example 1

A first sample was prepared with water 20 lb./1000 gal. (2.396 kg/m³)associative polymer. 4 lb./gal (0.4793 kg/L) of 20/40 Ottawa sand wasadded and then the sample was heated to 200° F. (93.33° C.). It wasobserved that the proppant had completely settled out of the solutionafter 3 hours.

A second sample was prepared with 20 lb./1000 gal. (2.396 kg/m³)associative polymer and 0.5% by weight hectorite clay nanoparticles. 4lb./gal (0.4793 kg/L) of 20/40 Ottawa sand was added and then the samplewas heated to 200° F. (93.33° C.). It was observed that the proppant wasstill suspended in solution after 16 hours.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

What is claimed is:
 1. A fracturing fluid comprising: a carrier fluid;an associative polymer; and clay nanoparticles.
 2. The fracturing fluidof claim 1, wherein the carrier fluid comprises aqueous fluids,non-aqueous fluids, slickwater fluids, aqueous gels, viscoelasticsurfactant gels, foamed gels, emulsions, and any combination thereof. 3.The fracturing fluid of claim 1, wherein the aqueous fluid comprisesfresh water, saltwater, brine, seawater, or any combination thereof. 4.The fracturing fluid of claim 1, wherein the associative polymer ispresent in an amount of about 1 lb/1000 gal to about 30 lb/1000 gal. 5.The fracturing fluid of claim 1, wherein the associative polymer has amolecular weight of about 10,000 Daltons to about 10,000,000 Daltons. 6.The fracturing fluid of claim 1, wherein the associative polymercomprises an acrylamide polymer, methacrylamide polymer, acrylatepolymer, methacrylate polymer, or combinations thereof.
 7. Thefracturing fluid of claim 6, wherein the associative polymer comprisesat least one hydrophobe.
 8. The fracturing fluid of claim 7, wherein theat least one hydrophobe comprises from 1 to 24 carbons.
 9. Thefracturing fluid of claim 7, wherein the at least one hydrophobe isselected from the group consisting of linear or branched alkyl, alkenyl,cycloalkyl, aryl, alkaryl, aralkyl hydrocarbons; halo-substituted alkyl,cycloalkyl, aryl, alkylaryl, acryloyl, arylakyl hydrocarbons; andmixtures thereof.
 10. The fracturing fluid of claim 7, wherein theassociative polymer comprises at least 0.25 to about 25 hydrophobicsegments per molecule.
 11. The fracturing fluid of claim 10, wherein thehydrophobic segments on the associative polymer comprise about 5% toabout 50% by weight of the total associative polymer.
 12. The fracturingfluid of claim 1, wherein the clay nanoparticles comprise hectorite,smectite, or combinations thereof.
 13. The fracturing fluid of claim 1,wherein the clay nanoparticles have a mean particle size of less than200 nm.
 14. The fracturing fluid of claim 1, wherein the claynanoparticles are present in an amount of about 0.5% to about 10% byweight of the associative polymer.
 15. The fracturing fluid of claim 1,further comprising proppant particulates present in an amount of about 1lb/gal to about 20 lb/gal.
 16. A fracturing fluid comprising: a carrierfluid; an associative polymer comprising at least one hydrophobecomprising from 1 to 24 carbons; and clay nanoparticles.
 17. Thefracturing fluid of claim 17, wherein the carrier fluid comprisesaqueous fluids, non-aqueous fluids, slickwater fluids, aqueous gels,viscoelastic surfactant gels, foamed gels, emulsions, and anycombination thereof.
 18. The fracturing fluid of claim 17, wherein theassociative polymer comprises an acrylamide polymer, methacrylamidepolymer, acrylate polymer, methacrylate polymer, or combinationsthereof, present in an amount of about 1 lb/1000 gal to about 30 lb/1000gal.
 19. The fracturing fluid of claim 17, wherein the at least onehydrophobe is selected from the group consisting of linear or branchedalkyl, alkenyl, cycloalkyl, aryl, alkaryl, aralkyl hydrocarbons;halo-substituted alkyl, cycloalkyl, aryl, alkylaryl, acryloyl, arylakylhydrocarbons; and mixtures thereof.
 20. The fracturing fluid of claim17, wherein the clay nanoparticles comprise hectorite, smectite, orcombinations thereof, present in an amount of about 0.5% to about 10% byweight of the associative polymer.